NO330142B1 - Process and system for increasing oil production from an oil well producing a mixture of oil and gas - Google Patents

Description

The field of the invention

This invention relates to a method and system for increasing oil production from oil wells that produce a mixture of oil and gas at an elevated pressure through a borehole penetrating an oil-bearing formation containing an injection zone and an oil-bearing zone by separating a portion of the gas from the mixture, as energy from at least part of the mixture is used to compress the separated gas at a surface and inject the compressed gas into the injection zone, and as further defined in the preamble of the attached method claim 1 and the attached system claim 15.

The background of the invention

In many oil fields, the oil-bearing formation includes a gas cap zone and an oil-bearing zone. Many of these fields produce a mixture of oil and gas with a gas-to-oil ratio (GOR) that increases as the field ages. This is the result of many factors well known to those experienced in the field. The mixture of gas and oil is typically separated into an oil part and a gas part at the surface. The gas part can be sold as a natural gas product, injected to maintain pressure in the gas jacket or similar. Furthermore, many such fields are located in parts of the world where it is economically difficult to bring the gas to market, and therefore the injection of the gas preserves its availability as a future resource, as well as maintaining pressure in the gas mantle.

Wells in such fields can produce mixtures that have GORs in excess of 2374.79 m<3>/m<3> at standard conditions of temperature and pressure (10,000 standard cubic feet per standard barrel (SCF/STB)). In such cases, the mixture may amount to less than 1% by volume of liquids in the well. GOR from 190 to 593.7 m<3>/m<3> at standard conditions of temperature and pressure (800 to 2,500 SCF/STB) is typically more than sufficient to bring the oil to the surface as a gas/oil mixture. The oil is normally dispersed as finely divided droplets or a mist in the gas produced in this way. In many such wells, a lot of water can be extracted with the oil. The term "oil" as used herein refers to hydrocarbon fluids produced from a formation. The surface facilities to separate and return the gas to the gas mantle obviously must have significant capacity when such mixtures are produced to return sufficient gas to the gas mantle or other depleted formations to sustain oil production.

In such fields, collection lines typically collect the fluids in joint lines which are then led to production facilities or the like, where crude oil, condensate and other hydrocarbon liquids are separated and transported as crude oil. Natural gas liquids are then extracted from the gas stream and optionally combined with the crude oil and condensate. A miscible solvent comprising carbon dioxide, nitrogen and a mixture of light hydrocarbons, such as the gas stream, can possibly be used for increased oil recovery or the like. The residual gas stream is then fed to a compressor where it is compressed for injection. The compressed gas is injected through injection wells, an annular section of a production well or the like into the gas mantle.

The size of the necessary surface equipment to process the mixture of gas and oil is obviously significant and can become a limiting factor on the amount of oil that can be produced from the formation, due to capacity limitations on the ability to handle the produced gas.

It is in US Patent No. 5,431,228 "Down Hole Gas-liquid Separator for Wells", issued July 11, 1995 to Weingarten et al. and transferred to the Atlantic Richfield Company, has been described that a screw separator can be used downhole to separate a gas and liquid stream for separate recovery at the surface. A gaseous part of the flow is extracted through an annular space in the well, the liquids being extracted through a production pipe.

In SPE 30637 "New Design for Compact Liquid-Gas Partial Separation: Down Hole and Surface Installations for Artificial Lift Applications" by Weingarten et al, it is described that screw separators as stated in US patent 5,431,228 can be used for down hole installations and on the surface for gas/liquid separation. Although such separations are particularly effective, as discussed for artificial or gas flow applications and the like, all of the gas and liquid is still recovered at the surface for processing as indicated. Consequently, the surface equipment for processing gas can still impose a significant limitation on the amount of oil that can be produced from an underground formation that produces oil as a mixture of gas and liquids.

Accordingly, a continuing search has been directed toward the development of methods which, with existing surface equipment, can increase the amount of oil that can be produced from underground formations producing a mixture of oil and gas with existing surface equipment.

US-A-5,794,697 relates to a process for increasing oil production from an oil well producing a mixture of oil and gas by separating a portion of the gas from the downhole mixture, compressing the separated gas downhole, and injecting the compressed the gas into the gas cap.

Summary of the Invention

In accordance with the present invention, it has been found that increased quantities of oil can be produced from an oil well producing a mixture of oil and gas at elevated pressure through a borehole penetrating an oil-bearing formation containing an oil-bearing zone and an injection zone, by to separate at least part of the gas from the oil and gas mixture to produce a separated gas and an oil-enriched mixture, energy from at least part of the oil and gas mixture being used to compress at a surface at least part of the separated gas to producing a compressed gas having sufficient pressure to be injected into the injection zone, the compressed gas being injected into the injection zone, and recovering at least the majority of the oil-enriched mixture.

The invention further comprises a system for increasing oil production from an oil well that produces a mixture of oil and gas at an elevated pressure through a borehole that penetrates a formation containing an oil-bearing zone and an injection zone, the system comprising a separator in fluid communication with the the oil-bearing zones, in a turbine which is positioned on the surface and which has an inlet in fluid connection with the separator, and a compressor positioned on the surface, the compressor being drive-wise connected to the turbine and having a gas inlet in fluid connection at a discharge outlet for separated gas on the separator, and in that the compressor further has a discharge outlet for compressed gas in fluid communication with the injection zone through a passage.

The initially mentioned method is characterized by the features that appear in the attached claim 1.

Further embodiments of the method appear from the subordinate claims 2 - 14.

The initially mentioned system is characterized by the features that appear in the attached claim 15.

Further embodiments of the system appear from the subordinate claims 16-32.

Brief description of the drawings

Fig. 1 is a schematic view of a production well according to the known technique for producing a mixture of oil and gas from an underground formation and an injection well for injecting gas back into a gas mantle in the oil-bearing formation. Fig. 2 is a schematic view of a downhole part for an embodiment of the system according to the present invention, in which system gas is separated downhole from liquids in a formation, produced through a production well to a surface, where it is compressed, and injected through a purpose-adapted injection well back to a gas mantle in the formation. Fig. 3 is a schematic view of a downhole part in a part for an alternative embodiment of the system according to the present invention, in which system gas is separated downhole from liquids in a formation, produced through a production well to a surface, where it is compressed , and is injected through another production well that functions as an injection well, back into a gas mantle in the formation. Fig. 4 is a schematic view of a downhole portion of an alternative embodiment of the system according to the present invention, in which system gas is separated downhole from fluids in a formation, produced through a production well to a surface, where it is compressed, and injected through a annulus in the production well back to a gas mantle in the formation. Fig. 5 is a schematic view of a downhole portion of an alternative embodiment of the system according to the present invention, in which system gas is separated at a surface from liquids produced from a formation, compressed and injected through the production well back into a gas mantle in the formation . Fig. 6 is a schematic flow diagram for a surface portion of an alternative embodiment of the system according to the present invention, for compressing gas using energy from an oil-enriched mixture of oil and gas. Fig. 7 is a schematic flow diagram for a surface portion of an alternative embodiment of the system according to the present invention for compressing gas using energy from gas from an oil well. Fig. 8 is a schematic flow diagram for a surface portion of an alternative embodiment of the system according to the present invention for compressing gas by means of a heater. Fig. 9 is a schematic flow diagram of a surface portion of an alternative embodiment of the system of the present invention for compressing gas using energy derived from an external source. Fig. 10 is a schematic flow diagram of a surface portion of an alternative embodiment of the system of the present invention for compressing gas using energy derived from an external source.

Mention of the preferred designs

When discussing the figures, the same numerical references will be used throughout to refer to the same or similar parts. Certain parts in the wells which are necessary for the correct operation of the wells, and certain pumps, valves and compressors which are necessary to achieve correct flow in fluids, have not been discussed for reasons of brevity.

In Fig. 1, which illustrates the prior art, a production oil well 10 is positioned in a borehole (not shown) to extend from a surface 12 through an overburden 14 to an oil-bearing formation 16. The production oil well 10 includes a first casing section 18, a second casing section 20, a third casing section 22 and a fourth casing section 24, and it is understood that the oil well 10 may alternatively include more or fewer than four casing sections. The use of such casing sections is well known to those experienced in the field of oil well completion. The casing pipes are of decreasing size and the fourth casing pipe 24 can be a slotted casing, a perforated pipe or the like. Although the production oil well 10 is shown as a well that has been curved to extend horizontally into the formation 16, it is not necessary for the well 10 to include such a horizontal section and alternatively the well 10 can only extend vertically into the formation 16. Such variations are well known to those experienced in the field of producing oil from underground formations.

The oil well 10 also includes a production pipe string, here designated as a production pipe 26, for the production of fluids from the well 10. The production pipe 26 extends upwards to a wellhead 28, schematically shown as a valve. The wellhead 28 contains the necessary valves and the like to control the flow of fluids to and from the oil well 10, the production pipe 26 and the like.

The formation 16 includes a selected injection zone 30 and an oil-bearing zone 32 which lies below the injection zone 30. The selected injection zone 30 can be a gas cap zone, a water-containing zone, an upper part of the oil-bearing zone 32, a depleted part of the formation 16 or the like. Pressure in the formation 16 is maintained by gas in the injection zone 30 and consequently in such fields it is desired to maintain the pressure in the injection zone by injecting gas as hydrocarbon fluids are produced from the formation 16. The formation pressure can be maintained by water injection, gas injection or both. The gas injection requires the removal of the liquids from the gas prior to compressing the gas, and injecting the gas back into the injection zone 30. The GOR of oil and gas mixtures recovered from such formations typically increases as the level of the oil-bearing zone decreases as a result of the removal of oil from the oil-bearing zone 16.

In the well 10, a packing 34 or a nipple with a locking stem or the like is used to prevent the flow of fluids in the annular space between the third casing section 22 and the fourth casing section 24. A packing 36 is positioned to prevent the flow of fluids in the annular space between the exterior of the production pipe 26 and the interior of the second casing section 20 and the portion to the interior of the third casing section 22 above packing 36. Fluids from the formation 16 can thus flow upwards through the production pipe 26 and the wellhead 28 for processing -ing equipment (not shown) at the surface, as previously described. Well 10, as shown, produces fluids under formation pressure and does not require a pump.

Also shown in Fig. 1 is an injection well 40 which comprises a first casing section 42, a second casing section 44, a third casing section 46 and an injection production pipe 48. A gasket 50 is positioned between the interior of the casing pipe 44 and the outside of the production pipe 48 for to prevent the upward flow of fluid between the production pipe 48 and the casing 44. Gas is injected to the injection zone 30 through perforations 52 in the third casing section 46. The flow of gases to the well 40 is controlled with a wellhead 53, schematically shown as a valve.

In operation, gas produced from the well 10 is injected into the injection zone 30 through the injection well 40. The injected gas thereby maintains pressure in the formation 16 and is still available for production and use as a fuel or another resource at a later time if desired.

In oil wells that produce exceptionally large quantities of gas, the need to handle the large quantity of gas at the surface can limit the ability of the formation to produce oil. Installation of sufficient gas assembly equipment to separate the large amount of gas from the oil for use as a product, or for injection into the injection zone 30, can be prohibitively expensive.

Fig. 2 shows an embodiment of the downhole part according to the present invention, which embodiment enables the separation and injection of at least part of the produced gas down the hole, and which embodiment enables the production of an oil-enriched mixture of oil and gas. An embodiment of a surface part according to the present invention, which surface part is complementary to the downhole part, is described below with respect to Fig. 6-10, in which embodiment surface facilities compress gas separated in the downhole part according to the present invention before the gas is injected by means of the downhole part.

The embodiment shown in Fig. 2 comprises a modification of the production oil well 10, in which a perforated or punched opening, recess or bore, such as the bore 60, is formed in the production pipe 26 in a manner well known to those experienced in the field. The bore 60 may optionally include a valve (not shown), such as a gas lift valve, a check valve, a drilling insert or the like, positioned therein to control the through flow of fluids. A downhole separator 70 is positioned inside the production pipe 26 so that a gas discharge outlet (not shown) on the separator is aligned with the bore 60 for discharge therethrough. The separator 70 may be any of a number of different types of separators, such as a screw separator, a cyclone separator, a rotary centrifugal separator, or the like. Screw separators and their positioning are mentioned and discussed in more detail in US Patent No. 5,431,228, "Down Hole Gas Liquid Separator for Wells", issued on July 11, 1995 to Jean S. Weingarten et al. and in "New Design for Compact-Liquid Gas Partial Separation: Down Hole and Surface Installations for Artificial Lift Applications", Jean S. Weingarten et al., SPE 30637 presented 22-25 October 1995, both of these references are incorporated herein in their entirety by reference. Such separators and their positioning downhole are considered well known to those skilled in the art and are effective in separating at least the bulk of the gas from a flowing stream of liquid (e.g. oil) and gas by causing the fluid -the mixture flows around a circular path, so that heavier phases, i.e. the liquids, are thereby forced outwards by gravity and upwards to the production pipe 26 for recovery at the surface 12. The lighter phases in the mixture, i.e. the gases, are displaced inwards into the separator 70 away from the heavier phases and thereby separated from the liquids, and flows from the separator 70 through the separator gas outlet, the bore 60 and up through an annulus 72, formed between the second casing section 20 and the production pipe 26, to the surface 12.

As schematically shown in Fig. 2, an oil-enriched mixture line 80 and a gas line 82 are connected to form fluid communication between the wellhead 28 and the annulus 72, respectively, and surface facilities designed to compress the gas, which will be described in more detail below with respect to Fig .6-10. A gas return line 84 is connected to provide fluid communication between a surface facility discharge outlet and the injection-production pipe 48 .

In operation of the system shown in Fig. 2, a mixture of oil and gas (which may also include other fluids, such as water) flows from the oil-bearing formation 32 through the fourth and third casing sections 24 and 22, respectively, to the production pipe 26, and to the separator 70, as schematically shown with arrows 90. The separator 70 separates at least a part of the gas from the mixture of oil and gas in the oil well 10 to produce a separated gas and an oil-enriched mixture. As shown schematically by arrows 92, the oil-enriched mixture produced by the separator 70 is delivered up to the production pipe 26 and through the wellhead 28 and the oil-enriched mixture line 80 to surface facilities described below. As shown schematically by an arrow 94, the separated gas is discharged from the separator 70 through the bore 60 to the annulus 72. The separated gas then flows up through the annulus 72 and the gas line 82 to surface facilities, as described below, which facilities compress the gas to a pressure that is sufficient to enable the gas to be injected into the injection zone 30, such a pressure being hereinafter referred to as an "injection pressure". The gas that is compressed to the injection pressure with the surface facilities is discharged from the surface facilities through the gas return line 84 to the injection production pipe 48 in the well 40, as shown schematically by an arrow 96, and to the injection zone 30. As a result of pressure and friction losses incurred as the gas is injected down into the hole, the aforementioned injection pressure preferably exceeds the pressure of the gas in the injection zone 30, minus the pressure of the gas in the injection production pipe 48, plus pressure loss incurred from friction as the gas is injected downhole.

Although only one well 10 is shown in Fig. 2, several wells similar to the well 10 can produce gas which is compressed with surface facilities and injected through the purpose-fitted injection well 40 to the injection zone 30.

In an alternative embodiment of the system shown in Fig. 2, the separator 70 may be formed with a transition device (not shown), which is well known to those skilled in the art, to direct separated gas from the separator to the production pipe 26 rather than the annulus 72, and lead the oil-enriched mixture from the separator to the annulus 72 rather than the production pipe 26. The line 80 for the oil-enriched mixture would then be connected in fluid connection with the annulus 72 rather than the production pipe 26, and the gas line 82 would be connected in fluid connection with the production pipe 26 rather than the annulus 72. Operation of a such alternative embodiment would otherwise be substantially similar to the operation of the embodiment shown in Fig. 2.

By using the system shown in Fig. 2, part of the gas downhole is separated from the oil/gas mixture and as a result the separated gas suffers less pressure loss and less friction loss and therefore maintains a significantly greater pressure while it is produced to the surface, than it would if it was produced in combination with the oil/gas mixture. Downhole separation of the gas from the oil/gas mixture also relieves the load on surface facilities to separate gas from the oil/gas mixture. In many fields it is not uncommon to encounter GOR values as high as 2374.79 m<3>/m<3> (10,000 SCF/STB). GOR values from 190 to 593.7 m<3>/m<3> (800 to 2,500 SCF/STB) are generally more than sufficient to bring the produced fluids to the surface. A significant amount of gas can thus be separated down the hole without any damage to the production process. This significantly increases the amount of oil that can be extracted from formations that produce gas and oil in a mixture, which extraction is limited by the available handling capacity for the amount of gas at the surface. In addition, the system in Fig. 2 facilitates the measurement of the gas separation efficiency and composition of gas injected downhole.

In Fig. 3, an alternative embodiment of the system of Fig. 2 is shown. An additional hole 62, similar to hole 60, is perforated, punched or otherwise formed in the production pipe below the separator 70, and a valve (not shown), such as a gas lift valve, a non-return valve, a drilling insert or the like, is positioned therein to control the flow of fluids from there in a manner well known in the field. A production pipe end extension 100 is placed in a lower end 26a of the production pipe 26. A gasket 102 is positioned between the production pipe end extension 100 and the production pipe 26 to prevent fluid connection between them, and a gasket 104 is inserted between the production pipe end extension 100 and the third casing section 22 to prevent fluid connection between these. A limited annular space 106 is thus defined between the production pipe end extension 100 and the third casing section 22 and between the seals 36, 102 and 104. The third casing section 22 is perforated with the perforation 108 to provide fluid connection between the injection zone 30 and the annular space 106. The production pipe end extension 100 is equipped with a first check valve 110 suitably positioned to allow fluid to flow only from the production tubing end extension 100 to the annulus 106, therefore preventing backflow. The production pipe end extension 100 is equipped with a second check valve 112 suitably positioned to allow fluid to flow only from that portion of the third casing 22 below the packing 104 to the production pipe end extension 100, therefore preventing backflow. The positioning of the production pipe end extension 100, the gaskets 102 and 104 and the check valve 110 and 112 is considered well known to those skilled in the art, and will therefore not be discussed further.

As further shown in Fig. 3, instead of the well 40 (Fig. 2), a well 10' is substantially identical to the well 10, except for its location in the formation 16. All components of the well 10' are identical to the same reference numbers as the components of well 10, except that the numerical references for well 10 are marked. Because of. the essential similarity of the wells 10 and 10', no further discussion of the well 10' is considered necessary. It is noted, however, that the gas return line 84 is connected in fluid connection with the annulus 72' to the well 10'.

In the operation of the system shown in Fig. 3, in which the well 10 can be operated as a production well and the well 10' can be operated as an injection well, a mixture of oil and gas flows from the oil-bearing formation 32 through, respectively. fourth and third casing sections 24 and 22 through the second check valve 112 and the production tubing end extension 100 to the production tubing 26 and to the separator 70, as schematically shown by arrows 90. The valve positioned in the hole 62 prevents the mixture of oil and gas from flowing through the hole 62 to the annulus 72. The separator 70 separates at least part of the gas from the mixture of oil and gas in the oil well to produce a separated gas and an oil-enriched mixture. As shown schematically by arrows 92, the oil-enriched mixture produced by the separator 70 is delivered up to the production pipe 26 and through the wellhead 28 and the oil-enriched mixture line 80 to surface facilities described below. As shown schematically by arrow 94, separated gas is discharged from separator 70 through bore 60 to annulus 72. The separated gas then flows upward through annulus 72 and gas line 82 to surface facilities which compress the gas to the injection pressure as defined above. As schematically shown with arrow 96, compressed gas is discharged from the surface facilities through the gas return line 84 to the annulus 72' in the well 10' and through the bore 62' to the production pipe 26'. The gas in the production pipe 26' flows through the production pipe end extension 100', the check valve 110' and to the injection zone 30, and the check valve 112' prevents the flow of the gas to the oil-bearing formation 32.

Although only one well 10 and only one well 10' are shown in Fig. 3, one or more wells, similar to the well 10, can produce gas which is compressed with surface facilities and injected through one or more wells similar to the injection well 10' to the injection zone 30. .Furthermore, wells can alternatively be used as production wells, and during their non-production cycles, as injection wells. The well 10 shown in Fig. 3 can e.g. is used as an injection well during its non-production cycle, while well 10' is used as a production well that produces gas that is injected into well 10.

In an alternative embodiment of the system shown in Fig. 3, the separators 70 and 70' may be formed with a transition device (not shown), well known to those skilled in the art, to direct separated gas from the separator to the production pipe 26 or 26' rather than the annulus 72 or 72', and lead the oil-enriched mixture from the separator to the annulus 72 or 72' rather than the production pipe 26 or 26'. The line 80 for the oil-enriched mixture would then be connected in fluid connection with the annulus 72 rather than the production pipe 26, and the gas line 82 would be connected in fluid connection with the production pipe 26 rather than the annulus 72. Operation of such an alternative embodiment would otherwise be essentially similar to the operation of the embodiment shown in Fig. 3 .

With the use of the system shown in Fig. 3, not only is part of the gas separated from the oil/gas mixture downhole and the gas pressure is thereby mainly maintained, and the measurement of the separation efficiency and the injection gas composition is facilitated as with the system in Fig. 2, but in addition the system in Fig. 3 does not require a suitable injection well to inject gas down the hole. The system in Fig. 3 enables production wells to be used more efficiently as they can be used as injection wells during their cycle without production.

In Fig. 4 is shown a modified part of an alternative embodiment of the system in Fig. 2. Separators 70 are positioned in a tubular element 120 positioned in a lower end 26a of the production pipe 26. The positioning of tubular elements with cable procedures or coiled pipes is well known to those with experience in the field and will not be discussed. A gasket 122 or a nipple with a locking stem or the like is positioned above the bore 60 and between an upper end 120a of the tubular element 120 and the production pipe 26 to control the flow of fluids through an annulus 124 which is defined by the production pipe, and which is defined between the tubular member 120 and the portion of the production pipe 26 that extends below the packing 122. A packing 126 is positioned below the packings 36 and 122 between a lower end 120b of the tubular member 120 and the third casing section 22 to control the flow of fluids in a confined annular space 128 defined between the tubular member 120 and the third casing section 22 and between the gaskets 36, 122 and 126. The third casing section 22 is perforated with perforations 130 to form fluid communication between the injection zone 30 and the annular room 128. A coiled pipe 132 is positioned in the production pipe 26 to form a fluid connection between a gas outlet 70a in the separator 70 and a gas line 82 to surface facilities described below. A "coil-through-production tubing" annulus 134 defined between production tubing 26 and coil tubing 132 provides fluid communication between an oil-enriched mixture outlet 70b in the separator 70 and the oil-enriched mixture line 80 to surface facilities. The gas return line 84 is connected in fluid communication between the surface facilities and the annulus 72 (with respect to Fig. 4 referred to as a "production pipe-through-conveyor" annulus) to conduct compressed gas to the annulus 72 for injection into the formation 16.

In operation of the system shown in Fig. 4, a mixture of oil and gas flows from the oil-bearing formation 32 through the fourth and third casing sections 24 and 22, respectively (Fig. 2) to the tubular member 120 and to the separator 70, as schematically shown with arrows 90. The separator 70 separates at least a portion of the gas from the oil and gas mixture in the oil well to produce a separated gas and an oil-enriched mixture. As shown schematically by arrows 92, the oil-enriched mixture produced by the separator 70 is delivered upward through the outlet 70b, the coil-through-production tubing annulus 134, the wellhead 28 (Fig. 2) and the oil-enriched mixture line 80 to surface facilities described below. As shown schematically by arrow 94, the separated gas produced by separator 70 is delivered upward through gas outlet 70a, coil tube 132, gas line 82 and to surface facilities which compress the gas to the injection pressure defined above. Compressed gas is discharged from the surface facilities through the gas return line 84 to the production pipe-through-casing annulus 72. As shown schematically by arrow 96, compressed gas in the production pipe-through-casing annulus 72 is routed through the borehole 60 to and through the production pipe-overriding annulus 124, the annular space 128, the perforations 130 and to the injection zone 30.

In an alternative embodiment of the system shown in Fig. 4, the separator 70 may be formed with a transition device (not shown), which is well known to those skilled in the art, to direct separated gas from the separator to the annulus 134 rather than the production pipe 132, and to lead the oil-enriched mixture from the separator to the production pipe 132 rather than the annulus 134. The oil-enriched mixture line 80 would then be connected in fluid connection with the production pipe 132 rather than the annulus 134, and the gas line 82 would be connected in fluid connection with the annulus 134 rather than the production pipe 132. Operation of such alternative embodiment would otherwise be substantially similar to the operation of the embodiment shown in Fig. 4.

In a further alternative embodiment of the system shown in Fig. 4, the system can be designed without the tubular member 120, the packing 122 and 126, and the bore 60, by replacing the packing 126 with the packing 36 and extending the production pipe 26 to and through the packing 36. Operation of such an alternative embodiment is substantially similar to the operation of the embodiment shown in Fig. 4, except that the mixture of oil and gas flows through the production pipe 26 without flowing through the tubular member 120, and compressed gas flows through the annulus 72 to the injection zone 30 without flowing through the bore 60 and through the annulus 124.

The use of the system shown in Fig. 4 not only separates part of the gas from the oil/gas mixture downhole, and the gas pressure is maintained and the measurement of the separation efficiency and injection gas composition is simplified as with the system in Fig. 2, but in addition the system in Fig. 4 does not require an additional well to inject gas downhole and thus does not require a significant amount of pipelines and valves at the surface to connect different wells.

In Fig. 5, an alternative embodiment of the system of Fig. 4 is shown, in which embodiment the separator 70 is positioned at the surface 12. Because there is no downhole separation of the gas from the produced oil and gas, coiled tubing is not run down the production tubing 26 as was in the system in Fig. 4. The system shown in Fig. 5 is otherwise essentially similar to the system shown in Fig. 4.

Operation of the system in Fig. 5 is similar to the operation of the system in Fig. 4, except that oil and gas produced from the formation 16 are separated by the separator 70 positioned at the surface 12. The arrows 90 thus constitute the flow of a mixture of oil and gas from the oil-bearing the formation 32 through the fourth and third casing sections 24 and 22, respectively, through the tubular member 120 and the production pipe 26 and to the separator 70 located at the surface 12. The separator 70 separates at least a portion of the gas from the oil and gas mixture in the oil well to produce a separated gas and an oil-enriched mixture. The oil-enriched mixture produced with the separator 70 is discharged through the outlet 70b to the oil-enriched mixture line 80 to surface facilities described below. Separated gas produced with the separator 70 is discharged through the gas outlet 70a and the gas line 82 to surface facilities which compress the gas to the injection pressure defined above. Compressed gas empties from the surface facilities through the gas return line 84 to the annulus 72. As schematically shown by arrow 96, compressed gas in the annulus 72 is directed through the bore 60 to and through the annulus 124, the annular space 128, the perforations 130 and to the injection zone 30.

In an alternative embodiment of the system shown in Fig. 5, the system can be designed without the tubular member 120, the packing 122 and 126 and the bore 60 by replacing the packing 126 with the packing 36 and extending the production pipe 26 to and through the packing 36. Operation of such alternative embodiment is substantially similar to the operation of the embodiment shown in Fig. 5, except that the mixture of oil and gas flows through the production pipe 26 without flowing through the tubular member 120, and compressed gas flows through the annulus 72 to the injection zone 30 without flowing through the bore 60 and through the annulus 124.

With the use of the system shown in Fig. 5, the separator 70 is more accessible than it was in the systems discussed above, coiled tubing is not required and the well 10 enables the cable tool to pass through it. As with the previous systems, the separation efficiency and injection gas composition can be measured. Furthermore, an additional well is not required to inject gas down the hole. Thus, a significant amount of pipelines and valves are not required at the surface to connect different wells.

In Fig. 6-10, five embodiments of a surface part of the present invention are shown in which embodiments gas, after it has been separated and before it is injected downhole, is compressed by means of surface facilities mentioned in the discussion above of the embodiment of the downhole part according to the present invention invention shown in Fig. 2-5. As previously expressed, the surface portion of the present invention is complementary to the downhole portion and in the later discussion the embodiments of the surface portion shall be understood as connected through the line 80 for oil-enriched mixture, the gas line 82 and the gas return line 84 to any of the embodiments of the downhole portion described with respect to Fig 2-5.

The embodiment of the surface portion of the present invention shown in Fig. 6 comprises a suitable compressor 200 which is drive-connected through a shaft 202 to a suitable turbine 204. The compressor 200 is connected to the gas line 82 to receive gas through it, and to the gas return line 84 to drain gas to this. The compressor 200 may be an axial, radial or mixed flow compressor or the like, not designed to compress gas received through the gas line 82 to the injection pressure, defined above, and to discharge compressed gas to the gas return line 84. Compressors such as the compressor 200 are considered well known to those of experience in the area, and will not be discussed further.

The turbine 204 is connected in parallel with the oil-enriched mixture line 80 to receive through a line 80a, and for and driven by at least a portion of the oil-enriched mixture flowing through the oil-enriched mixture line 80, and to discharge the received mixture through a line 80b to line 80 for oil-enriched mixture. A suitable valve 206 is positioned in the oil-enriched mixture conduit 80 between conduits 80a and 80b to control the amount of the oil-enriched mixture flowing through the turbine 204. The turbine 204 may be a radial or axial turbine, such as a turbine expander, a hydraulic turbine, a two-phase turbine or similar. Turbine expanders, hydraulic turbines and two-phase turbines are considered well known to those skilled in the art and are effective for receiving a stream of fluids, such as the oil-enriched mixture of the present invention, and for developing, from the received stream of fluids, turning force exerted on a shaft, such as the shaft 202, such flow of fluids predominantly comprising gases, liquids and mixtures of gases and liquids respectively. In particular, two-phase turbines are more fully described and discussed in US Patent No. 5,385,446, entitled "Hybrid Two-Phase Turbine", issued January 31, 1995 to Lance G. Hays, which patent is incorporated herein in its entirety by reference .

In operation of the system shown in Fig. 6, if valve 206 is open, the oil-enriched mixture flows through the oil-enriched mixture line 80 so that it generally bypasses the turbine 204, to a pipeline (not shown) that carries the mixture to downstream processing facilities ( not shown) which are considered well-known in the area, and will not be discussed. When the turbine 204 is bypassed by the oil-enriched mixture as a result of the valve 206 being open, the turbine 204 does not drive the compressor 200 and the gas in the gas line 82 is not compressed and cannot be injected into the formation 16 (not shown). If valve 206 is closed, then all of the oil-enriched mixture flows through line 80 for oil-enriched mixture also through line 80a to and through turbine 204, and through line 80b to the pipeline (not shown) that carries the mixture to downstream processing facilities. As the mixture flows through the turbine 204, rotational motion is imparted to the turbine which then imparts rotational motion to the shaft 202 and drives the compressor 200. The compressor 200 receives gas through the gas line 82 and, as the compressor rotates, compresses the gas received from the line 82 to the injection pressure defined above. Compressed gas is discharged from the compressor 200 to the gas return line 84 and to the injection zone 30 (Fig. 2-5) as discussed above. The valve 206 can only be partially closed to direct only a portion of the oil-enriched mixture to the turbine 204, in which case the pressure imparted by the compressor 200 to the gas received through the gas line 82 will be associated with the extent to which the valve 206 is closed. The valve 206 is preferably closed only enough to enable the compressor 200 to compress gas sufficiently for injection into the formation, thereby maintaining pressure in the mixture in the line 80 for oil-enriched mixture.

With the use of the foregoing system shown in Fig. 6, formation pressure can be used to inexpensively compress gas at a well and inject the gas downhole without the need to send the gas to a central compressor facility.

In Fig. 7, an alternative embodiment of the system in Fig. 6 is shown, in which embodiment the turbine 204 is operated with at least part of the gas taken from gas line 82 rather than at least part of the oil-enriched mixture taken from line 80 for oil-enriched mixture. In this regard, a line 82a is connected to provide fluid communication between the gas line 82 and an inlet (not shown) to the turbine 204. A valve 210 is positioned in the gas line 82 downstream of the start of the line 82a to control the distribution of gas flow between the compressor 200 and the turbine 204. Line 80b is connected to provide fluid communication between an outlet (not shown) in turbine 204 and line 80 for oil-enriched mixture.

In operation of the system shown in Fig. 7, the oil enriched mixture flows through the oil enriched mixture line 80 directly to a pipeline (not shown) which carries the mixture to downstream processing facilities which are considered well known in the art and will not be discussed. The valve 210 is activated to control the gas flow emitted from the gas line 82 to the turbine 204 and to the compressor 200, so that a correct flow balance can be maintained to allow the turbine to develop the necessary power driving the compressor, so that the operation of this is thus controlled. Correct operation of the system in Fig. 7 therefore requires that the valve 210 is neither fully opened nor fully closed, but rather that it is only partially opened, so that part of the gas in the gas line 82 is led to the compressor 200 and part is led through the line 82a to the turbine 204. Gas that does not flow through the valve 210 drives the turbine 204 that drives the compressor 200, and gas that flows through the valve 210 is compressed by the compressor 200. The portion of gas that flows through the turbine 204 is preferably optimized to enable the turbine 204 to drive the compressor 200 to compressing the gas flowing through valve 210 to the injection pressure defined above. Gas is discharged from the turbine 204 through the line 80b to the oil enriched mixture line 80 and to the pipeline and downstream processing facilities (not shown), and compressed gas is discharged from the compressor 200 to the gas return line 84 and to the injection zone (Figs. 2-5) as discussed above. .

In Fig. 8, an alternative embodiment of the system in Fig. 6 is shown. The gas line 82 is connected to carry gas to a separator 220, such as a suction liquid separator or the like, designed to produce a separated gas and a separated liquid from the gas received through the gas line 82. A line 222 is connected to the separator 220 to lead the separated gas produced with the separator 220 to the compressor 200, and a line 224 is connected to the separator 220 to lead separated liquids produced with the separator 220 to a line 226, a line 228 and to a pipeline (not shown). A line 230 leads a portion of the gas in the line 222 to a heating device, such as a gas-powered furnace 232, for combustion therein. Although not shown, it will be understood that suitable valves and the like are formed on conduits 222 and 230 to control gas flow distribution through these conduits in a manner well known to those skilled in the art. A line 234 is connected to carry compressed gas discharged from the compressor 200 to a gas-to-gas heat exchanger 236, and the gas return line 84 is connected to carry the compressed gas from the heat exchanger 236 to an injection well, as discussed above.

The oil-enriched mixture line 80 is connected to convey the oil-enriched mixture to a separator 240, such as an expander suction separator or the like, designed to produce a separated gas and a separated liquid from the oil-enriched mixture received through the oil-enriched mixture line 80. A conduit 242 is connected to the separator 240 to convey the separated gas produced by the separator 240 to the heat exchanger 236, and a conduit 226 is connected to the separator 240 to convey separated liquids produced by the separator 240 to conduit 228 and to a pipeline (not shown ). A line 244 is connected to the heat exchanger 236 to lead the separated gas produced with the separator 240 from the heat exchanger 236 to the furnace 232 for heating therein. A line 246 is connected to lead the separated gas produced by the separator 240 and heated in the furnace 232 to an inlet (not shown) in the turbine 204. The line 228 is connected to lead gas from the turbine 204 to the pipeline (not shown).

In operation of the system shown in Fig. 8, the oil-enriched mixture flows through the oil-enriched mixture line 80 to the separator 240 which produces a separated gas and a separated liquid. The separated liquids (ie, oil enriched mixture) flow through lines 226 and 228 to the pipeline and downstream processing facilities. The separated gas produced by separator 240 flows through line 242 to heat exchanger 236, which transfers heat to the separated gas through line 244 to furnace 232, which further heats the separated gas, and through line 246 to turbine 204. The heated gas drives the turbine 204, which then drives the compressor 200, and the gas is then discharged from the turbine through line 228 to the pipeline (not shown). The heat transferred through the heat exchanger 236 and the heater 232 to the gas driving the turbine 204 should be sufficient to maintain a temperature in the gas high enough as it is discharged from the turbine to prevent the paraffin and/or hydrates from forming. in the gas.

Gas in the gas line 82 flows to the separator 220 which produces from the separated gas and the separated liquids. The separated liquids produced by the separator 220 flow through lines 224, 226 and 228 to the pipeline (not shown) and to downstream processing facilities. Part of the separated gas produced with the separator 220 flows through line 222 to the compressor 200, and another part of the separated gas flows through lines 222 and 230 to the furnace 232. The gas taken to the furnace through line 230 is burned to develop heat for to heat the gas flowing from line 244 to the furnace. The gas led through the line 222 to the compressor 200 is compressed to the injection pressure defined above. Compressed gas is then emptied from the compressor 200 through the line 234 to the heat exchanger 236 which transfers heat from the compressed gas led with the line 234 to the separated gas led with the line 242. The compressed gas is then led with the gas return line 84 to an injection well (not shown) for injection to the injection zone 30 (Fig. 2-5) as discussed above.

Although the furnace 232 is shown as a gas-fired furnace, any suitable heating device may be used. If electricity is available, e.g. an electric heater is used instead of the gas-driven heater 232 and thereby preserve fuel gas and enable a larger amount of gas to be compressed and injected into the injection zone 30 (Fig. 2-5).

In Fig. 9, an alternative embodiment of the system in Fig. 8 is shown, the compressor 200 being a first-stage compressor. Line 234 (Fig. 8) is shown in Fig. 9 as two lines 234a and 234b, and a suitable second stage compressor 250 is inserted between lines 234a and 234b to further compress gas discharged from compressor 200 before the gas is passed through heat exchanger 236 and to the gas return line. 84. The second stage compressor 250 is driven by any available suitable power source 252, such as an electric driven motor, a gas driven turbine, a diesel engine, a turbine driven by fluids taken from available high pressure/performance flow lines or the like. Because the compressor 250 adds heat to the compressed gas, which heat is transferred via the heat exchanger 236 to the gas led to the turbine 204, the furnace 232 used in the system of Fig.

8 in the system of Fig. 9.

In the operation of the system shown in Fig. 9, the oil-enriched mixture flows through the oil-enriched mixture line 80 to the separator 240 which produces a separated gas and a separated liquid. The separated liquids (ie, oil enriched mixture) flow through lines 226 and 228 to the pipeline and downstream processing facilities. The separated gas produced by the separator 240 flows through line 242 to the heat exchanger 236, which transfers heat to the separated gas and through line 246 to the turbine 204. The heated gas drives the turbine 204, which then drives the compressor 200 and the gas is then discharged from the turbine 204 through wire 228 to the pipeline (not shown). The heat transferred from the heat exchanger 236 to the gas driving the turbine 204 should be sufficient to maintain a temperature in that gas great enough, as it is discharged from the turbine, to prevent paraffins and/or hydrates from forming in the gas.

Gas in the gas line 82 flows to the separator 220 which produces from the separated gas and the separated liquids. The separated liquids produced by the separator 220 flow through lines 224, 226 and 228 to the pipeline and to downstream processing facilities (not shown). The separated gas produced by separator 220 flows through line 222 to compressor 200 and through line 234a to second-stage compressor 250. Compressors 200 and 250 compress the gas to the injection pressure, defined above, and as a consequence of the compression, the gas is also heated. The second stage compressor 250 discharges the compressed and heated gas through the line 234b to the heat exchanger 236 which transfers heat from the compressed and heated gas to the separated gas produced by the separator 240. The compressed gas is then conveyed from the heat exchanger 236 by the gas return line 84 to an injection well (not shown) for injection to the injection zone 30 (Fig. 2-5) as discussed above.

In Fig. 10, an alternative embodiment of the system in Fig. 9 is shown, in which embodiment a different separation technique is used. In this regard, the oil-enriched mixture line 80 is connected directly to the pipeline (not shown) to convey the oil-enriched mixture to downstream processing facilities (not shown). The gas line 82 is connected to lead separated gas directly to the heat exchanger 236, and the line 246 is connected to lead the separated gas discharged from the heat exchanger to the inlet (not shown) in the turbine 204. The outlet (not shown) in the turbine 204 is connected through a line 254 for conveying gas discharged from the turbine to a separator 256, such as a screw separator, a cyclone separator, a rotary centrifugal separator or the like, in the same manner as the separator 70 described above with respect to Figs. 2-5. The separator 256 is designed to separate at least a portion of the gas from the mixture of gas and liquids discharged from the turbine 204 to produce a separated gas to a line 258 and a separated mixture of liquids and gas to a line 260. The line 258 is connected to lead the separated gas produced by the separator 256 to an inlet (not shown) of the compressor 200, and line 260 is connected to lead the separated mixture of liquids and gas produced by the separator 256 to the oil enriched mixture line 80 for transfer to the pipeline (not shown).

In operation of the system shown in Fig. 10, the oil-enriched mixture flows through the oil-enriched mixture line 80 to the pipeline (not shown) which carries the mixture to downstream facilities for further processing. Separated gas is passed through gas line 82 to heat exchanger 236 which transfers heat to the separated gas and through line 246 to turbine 204. The heated, separated gas drives turbine 204, which then drives compressor 200, and the gas, with certain condensate liquids, is then discharged from the turbine through line 254 to separator 256. Separator 256 separates at least a portion of the gas from the mixture of gas and liquids exhausted from turbine 204 to produce a separated gas to line 258 and a separated mixture of liquids and gas to line 260. The separated mixture of gas and liquids produced with the separator 256, is passed through the line 260 to the oil-enriched mixture line 80 which transfers the mixture with the oil-enriched mixture to the pipeline and downstream processing equipment (not shown). The separated gas produced by separator 256 is passed through line 258 to and through compressor 200, and through line 234a to and through second stage compressor 250. Compressors 200 and 250 are driven by turbine 204 and power source 252, respectively, to compress the gas to the injection pressure, defined above, and as a consequence of the compression, the gas is also heated. The compressor 250 discharges the compressed and heated gas through the line 234b to the heat exchanger 236 which transfers heat from the compressed and heated gas to the separated gas carried by the gas line 82. The heat transferred through the heat exchanger 236 to the separated gas, carried by the gas line 82 and discharged from the heat exchanger to the conduit 246 to drive the turbine 204, should be sufficient to maintain a temperature in the gas great enough, as it is discharged from the turbine, to prevent paraffins and/or hydrates from forming in the gas. The compressed gas is then fed from the heat exchanger 236 by the gas return line 84 to the injection well (not shown) for injection into the injection zone 30 (Fig. 2-5), as discussed above.

In an alternative embodiment of the system shown in Fig. 10, the system may be designed without the second stage compressor 250 and accompanying power source 252, and lines 234a and 234b may be connected to carry compressed gas from the compressor 200 to the heat exchanger 236. Operation of such an alternative embodiment would otherwise be essentially similar to the operation of the embodiment shown in Fig. 10.

The investment to install the system of the present invention in several wells to reduce the gas produced from a field is significantly less than the cost of providing further separation and compression equipment at the surface. It also does not require any fuel gas to drive the compression equipment, as the pressure or combustion of the flowing fluids can be used for this purpose. It also enables the injection of selected quantities of gas from individual wells into a downhole injection zone, such as a gas cap, from which wells oil production has been limited due to the capacity of the lines or production pipes to carry produced fluids away from the well, so that increased production is thereby enabled from such wells. It can also make certain formations, which have previously become uneconomic to produce from, economical to produce from due to the ability to inject the gas downhole.

Claims (32)

1. Method for increasing oil production from an oil well (10) which produces a mixture (90) of oil and gas at an elevated pressure through a borehole, which penetrates an oil-bearing formation (16), which contains an oil-bearing zone (32) and an injection zone (30), the method comprising: a) separating down the hole at least part of the gas from the mixture (90) of oil and gas to produce a separated gas (80) and an oil-enriched mixture (80), b) applying energy from at least a portion of the mixture (90) of oil and gas to compress at least a portion of the separated gas (82) to produce a compressed gas (84) having sufficient pressure to be injected into the injection zone; c) injecting the compressed gas (84) into the injection zone (30), and d) recovering at least a major portion of the oil-enriched mixture (80), characterized in that at least part of the separated gas (82) is compressed at the surface (12). 2. Method according to claim 1, characterized in that the borehole consists of a first borehole, and the injection step comprises that the compressed gas (84) is injected through a second borehole into the injection zone (30). 3. Method according to claim 1 or 2, characterized in that the method further comprises the step that the separated gas (82) is led to an annulus (72) in the oil well (10) for extraction of the separated gas (82) at the surface. 4. Method according to claim 1 or 3, characterized in that the injection step comprises injecting the compressed gas (84) through the oil well (10) into the injection zone (30). 5 Method according to any one of the preceding claims, characterized in that at least part of the mixture (90) of oil and gas consists of the oil-enriched mixture (80), and the energy use step further comprises: - driving a turbine (204) with at least a part (80a) of the oil-enriched mixture (80), - to drive a compressor (200) with the turbine (204), and - to compress with the compressor (200) at least a part of the separated gas (22) to produce it compressed the gas (84). 6. Method according to any one of claims 1 to 4, characterized in that at least part of the mixture (90) with oil and gas consists of a first part (82a) of the separated gas (82), at least part of the separated gas (22 ) is constituted by a second part of the separated gas (82), and the energy use step further comprises: - driving a turbine (204) with the first part (82a) of the separated gas (82), - driving a compressor (200) with the turbine (204), and - compressing with the compressor (200) the second part of the separated gas (82) to produce the compressed gas (84). 7. Method according to any one of claims 1 to 4 and claim 6, characterized in that at least part of the mixture (90) of oil and gas is made up of the oil-enriched mixture (80), the separated gas is made up of a first separated gas (222 ), and the energy utilization step further comprises: separating gas from the oil-enriched mixture (80) to produce a second separated gas (242), - driving a turbine (204) with the second separated gas (242), and - compressing with the compressor (200) at least a portion of the first separated gas (222) to produce the compressed gas (84). 8. Method according to any one of claims 1 to 4, characterized in that the mixture (90) of oil and gas consists of a first mixture of oil and gas, at least part of the first mixture of oil and gas is made up of the separated gas, the the separated gas is constituted by a first separated gas (246), and the energy utilization step further comprises: - driving a turbine (204) with the first separated gas (246) and discharging a second mixture (254) of oil and gas from the turbine (204) ), - driving a compressor (200) with the turbine (204), - separating at least part of the gas from the second mixture (254) of oil and gas to produce a second separated gas (256), and - compressing with the compressor (200) the second separated gas (258) to produce the compressed gas (80). 9. Method according to claim 7, characterized in that the second separated gas (242) is heated to produce a heated, second separated gas (246) before the turbine (204) is driven with this. 10. Method according to claim 9, characterized in that the second separated gas (242) is heated by passing through a heat exchange connection (236) with the compressed gas (84). 11. A method according to any one of claims 7, 9 and 10, characterized in that at least part of the first separated gas (222) is compressed with a first stage compressor (200) driven by the turbine (204) and a second stage compressor (250) to produce the compressed the gas (84). 12. Method according to claim 8, characterized in that the first separated gas (246) is heated to produce a heated first gas before the turbine (204) is driven with it. 13. Method according to claim 12, characterized in that the first separated gas (246) is heated by passing through a heat exchange connection (236) with the compressed gas (84). 14. A method according to any one of claims 8, 12 and 13, characterized in that at least a portion of the second separated gas (258) is compressed with a first stage compressor (200) driven by the turbine (204) and a second stage compressor (250) to produce the compressed the gas (84). 15. System for increasing oil production from an oil well (10) which produces a mixture (90) of oil and gas at an elevated pressure through a borehole, which penetrates a formation (16), which contains an oil-bearing zone (32) and a injection zone (30), the system comprising: - a downhole separator (70) in fluid communication with the oil-bearing zone (32), - a turbine (204) having an inlet in fluid communication with the separator (70) to receive fluids from the separator to drive the turbine, and - a compressor (200) which is drive-connected to the turbine (204), the compressor having a gas inlet in fluid connection with a discharge outlet (70a) on the separator (70) for separated gas, and the compressor further having a discharge outlet for compressed gas in fluid connection with the injection zone (30) through a passage, characterized in that the turbine (204) and the compressor (200) are positioned on the surface (12). 16. System according to claim 15, characterized in that the borehole is a first borehole and the passage is a second borehole. 17. System according to claim 15, characterized in that the borehole is a first borehole, the passage is a second borehole and the separator (70) is positioned in a production pipe string (26) in the first borehole and is in fluid connection with an annulus (72) formed between the production pipe string (26) ) and the first borehole, which annulus (72) is in fluid communication with the surface (12). 18. System according to claim 15, characterized in that the borehole is a first borehole, the passage is a second borehole and the separator (70) is positioned in a production pipe string (26) in the first borehole and is in fluid connection with an annulus (72) formed between the production pipe string (26) ) and the first borehole, which annulus (72) is in fluid communication with the surface (12), and that the system further comprises a tubular element (120) positioned in the production pipe string (26), a first check valve positioned in the tubular element to enable fluid flow from the tubular member to the injection zone (30), and a second check valve positioned in the tubular member to enable fluid flow from the oil conducting zone (32) to the tubular member. 19. System according to claim 15, characterized in that the passage extends through the borehole. 20. System according to claim 15, characterized in that the system further comprises: - a first production pipe string (26) positioned in the borehole and which has a lower production pipe string section in fluid connection with the injection zone (30), and an upper production pipe string section in fluid connection with the surface (12), - tubular element (120) positioned in the first production pipe, so that a first annulus is formed between the tubular element and the first production pipe string, the separator (70) being positioned inside the tubular element in fluid communication with the oil-carrying zone (32) through the tubular element, - a second production pipe string (132) positioned in the borehole in fluid connection with the discharge outlet (70a) for separated gas on the separator (70) and a gas inlet in the compressor (200), - a first annulus (134) bounded between the first and second production tubing strings (26,132), the first annulus being in fluid communication with an exhaust discharge outlet (70b) for oil-enriched mixture on the separator (70) and with the surface (12), - a second annular space defined between the first production pipe string and the casing, the second annular space being in fluid connection with the discharge outlet for compressed gas, - a third annular space defined between the first production pipe string and the tubular element, the third annulus being in fluid communication with the injection zone (30), and - a bore (60) formed in the first production tubing string (26) below the separator (70) to enable fluid communication between the second annulus and the third annulus , so that the passage extends from the compressed gas discharge outlet through the second passage, through the bore, through the third annulus and to the injection zone (30). 21. System according to claim 15, characterized in that the system further comprises: - a production pipe string (26) positioned in the borehole and which has a lower production pipe string section in fluid connection with the injection zone (30), and an upper production pipe string section in fluid connection with the separator (70), - a tubular member (120) positioned in the production tubing string (26) with a first gasket (122) positioned between the tubular member (120) and the production tubing string (26) and between the upper and lower production tubing string portions, and with a second gasket (126) ) positioned between the tubular element (120) and the borehole to effect fluid communication between the oil-bearing zone (32) and the upper production pipe section, and - a bore (60) formed in a wall of the lower production pipe string section, the bore being in fluid communication with a first annulus delimited between the production pipe string (26) and the borehole, and with a second annulus delimited between the production pipe string (26) and the tubular member (120). 22. System according to claim 15, characterized in that the fluids received from the separator (70) to drive the turbine (204) comprise at least a part of an oil-enriched mixture (80). 23. System according to claim 15, characterized in that the fluids received from the separator (70) to drive the turbine (204) comprise at least part of a separated gas (82). 24. System according to claim 15, characterized in that the fluids received from the separator (70) to drive the turbine (204) comprise a gaseous part of an oil-enriched mixture (80). 25. System according to claim 15, characterized in that the separator (70) is a first separator, and that the system further comprises: - a second separator (240) which has an inlet connected to receive an oil-enriched mixture (80) from the first separator, - a heater (232) having an inlet connected to receive from the second separator (240) a gaseous part (244) of the oil-enriched mixture, and - an inlet to the turbine (204) connected to receive from the heater (232) a heated gaseous portion (246) of the oil-enriched mixture to drive the turbine (204). 26. System according to claim 15, characterized in that the separator (70) is a first separator, and that the system further comprises: - a second separator (240) which has an inlet connected to receive an oil-enriched mixture (80) produced from the first separator, - a heat exchanger (236) having a first inlet connected to receive from the second separator (240) a gaseous portion (242) of the oil-enriched mixture, and a second inlet connected to receive a compressed gas (234) from the compressor (200) ), and - an inlet to the turbine (204) connected to receive from the heat exchanger (236) a heated gaseous portion (246) of the oil-enriched mixture to drive the turbine. 27. System according to claim 15, characterized in that the separator (70) is a first separator, the compressor (200) is a first-stage compressor (200), and that the system further comprises: - a second separator (240) which has an inlet connected to receive an oil-enriched mixture (80) from the first separator, - a second stage compressor (250) connected to receive a first compressed gas (234a) from the first stage compressor (200), and - an inlet to the turbine (204) connected to receive from the second separator ( 240), a gaseous portion (246) of the oil-enriched mixture to drive the turbine. 28. System according to claim 15, characterized in that the separator (70) is a first separator, the compressor (200) is a first-stage compressor (200), and that the system further comprises: - a second separator (240) which has an inlet connected to receive an oil-enriched mixture (80) from the first separator, - a second stage compressor (250) connected to receive a first compressed gas (234a) from the first stage compressor (200), - a heat exchanger (236) having a first inlet connected to receive from the second the separator (240) a gaseous portion (242) of the oil-enriched mixture, and a second inlet connected to receive a compressed gas (234b) from the second stage compressor (250), and an inlet to the turbine (204) connected to receive from the heat exchanger (236) a heated gaseous portion (246) of the oil-enriched mixture to drive the turbine. 29. System according to claim 15, characterized in that the separator (70) is a first separator, the compressor (200) is a first-stage compressor (200), and that the system further comprises: - a second-stage compressor (250) connected to receive a first compressed gas (234a) from the first stage compressor (200), - a heat exchanger (236) having a first inlet connected to the separated gas discharge outlet (70a) of the first separator (70) to receive the separated gas from the first separator, and a second inlet connected to receiving a second compressed gas (234b) from the second stage compressor (250), - an inlet to the turbine (204) connected to receive from the heat exchanger (236) a heated separated gas (246) for driving the turbine, and - a second separator (256 ) having an inlet connected to receive gas and liquids (254) from the turbine (204), and having a gas outlet in fluid communication with an inlet to the first compressor (200). 30. System according to claim 15, characterized in that the separator (70) is a first separator and the compressor (200) is a first-stage compressor (200), and that the system further comprises: - a second-stage compressor (250) connected to receive a first compressed gas (234a) from the first stage compressor (200), - an inlet to the turbine (204) connected to receive the separated gas (246) from the first separator to drive the turbine (204), and - a second separator (256) having an inlet connected for to receive gas (254) from the turbine (204), and having a gas outlet in fluid communication with an inlet to the first compressor (200). 31. System according to claim 15, characterized in that the separator (70) is a first separator, and that the system further comprises: - a heat exchanger (236) which has a first inlet connected to the discharge outlet (70a) for separated gas on the first separator (70) in order to receive the separated gas (82) from the first separator, and a second inlet connected to receive compressed gas (234) from the compressor (200), - an inlet to the turbine (204) connected to receive from the heat exchanger (236) a heated separated gas (246) to drive the turbine (204), and - a second separator (256) having an inlet connected to receive gas (254) from the turbine (204), and having a gas outlet in fluid communication with an inlet to the first compressor (200). 32. System according to claim 15, characterized in that the separator (70) is a first separator, and that the system further comprises: - an inlet to the turbine (204) connected to the discharge outlet (70a) for separated gas on the first separator (70) to receive the separated the gas from the first separator to drive the turbine (204), and - a second separator (256) having an inlet connected to receive gas (254) from the turbine (204), and having a gas outlet in fluid communication with an inlet to the first compressor (200).